Fracturing methods and systems

ABSTRACT

Hybrid gas fracturing methods and systems utilizing an early stage gas treatment fluid, which may contain a dispersed phase of fluid loss control agent particles, followed by a proppant stage(s) to form a fracture system having a branched tip region and a propped region between the branched tip region and the wellbore. Also, treatment fluids suitable for use in the methods and systems are disclosed.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

Gas fracturing, either with compressed gas alone or with proppant, hasbeen used to create conductive pathways in a subterranean formation andincrease fluid flow between the formation and the wellbore. The gas isinjected into the wellbore passing through the subterranean formation atvery high rates to offset high leakoff into the formation being treated.Even without proppant, the fractures created may have sufficientconductivity due to their length and dendricity to enable production ofreservoir fluids comparable to fractures in the same formationconventionally filled with proppant. Accordingly, there is a demand forfurther improvements in this area of technology.

SUMMARY

In some embodiments according to the disclosure herein, hybrid gasfracturing methods and systems are employed to obtain a branchedgas-fractured tip region and a propped region to communicate between thewellbore and the branched tip region.

In some embodiments, a method for treating a subterranean formationpenetrated by a wellbore may comprise injecting an early stagecomprising a continuous gas phase, which may be substantiallyproppant-free, into the formation above a fracturing pressure to form afracture system comprising a branched tip region; and injecting one ormore proppant stages, comprising a treatment fluid comprising proppantand having a viscosity greater than the early stage, into the formationbehind the early stage to form a propped region of the fracture systemto communicate between the wellbore and the branched tip region.

In some embodiments, a reservoir production system may comprise awellbore penetrating a subterranean formation; and the fracture systemobtained by the method described herein in fluid communication with thewellbore.

In some embodiments, a system to treat a subterranean formation maycomprise a subterranean formation penetrated by a wellbore; a gasinjection unit to supply a gas treatment fluid stage comprising acontinuous gas phase, which may be substantially free of proppant, tothe formation above a fracturing pressure to form a fracture systemcomprising a branched tip region; and a pump system to supply one ormore proppant stages, comprising a treatment fluid comprising proppantand having a viscosity greater than the gas treatment fluid stage, intothe fracture system behind the gas treatment fluid stage to form apropped region of the fracture system to communicate between thewellbore and the branched tip region.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features and advantages will be better understood byreference to the following detailed description when considered inconjunction with the accompanying drawings.

FIG. 1 schematically illustrates a fracture system with a branched tipregion formed by early-stage gas fracturing according to embodiments.

FIG. 2 schematically illustrates the fracture system of FIG. 1 followingsubsequent injection of one or more proppant stages according toembodiments.

FIG. 3 schematically illustrates a heterogeneously propped region of ahybrid fracture as seen generally along the lines 3-3 of FIG. 2following formation of proppant pillars and fracture closure accordingto embodiments.

DETAILED DESCRIPTION

For the purposes of promoting an understanding of the principles of thedisclosure, reference will now be made to some illustrative embodimentsof the current application. Like reference numerals used herein refer tolike parts in the various drawings. Reference numerals without suffixedletters refer to the part(s) in general; reference numerals withsuffixed letters refer to a specific one of the parts.

As used herein, “embodiments” refers to non-limiting examples of theapplication disclosed herein, whether claimed or not, which may beemployed or present alone or in any combination or permutation with oneor more other embodiments. Each embodiment disclosed herein should beregarded both as an added feature to be used with one or more otherembodiments, as well as an alternative to be used separately or in lieuof one or more other embodiments. It should be understood that nolimitation of the scope of the claimed subject matter is therebyintended, any alterations and further modifications in the illustratedembodiments, and any further applications of the principles of theapplication as illustrated therein as would normally occur to oneskilled in the art to which the disclosure relates are contemplatedherein.

Moreover, the schematic illustrations and descriptions provided hereinare understood to be examples only, and components and operations may becombined or divided, and added or removed, as well as re-ordered inwhole or part, unless stated explicitly to the contrary herein. Certainoperations illustrated may be implemented by a computer executing acomputer program product on a computer readable medium, where thecomputer program product comprises instructions causing the computer toexecute one or more of the operations, or to issue commands to otherdevices to execute one or more of the operations.

It should be understood that, although a substantial portion of thefollowing detailed description may be provided in the context ofoilfield fracturing operations, other oilfield operations such ascementing, gravel packing, etc., or even non-oilfield well treatmentoperations, can utilize and benefit as well from the instant disclosure.

In some embodiments disclosed herein, a method for treating asubterranean formation penetrated by a wellbore may comprise injecting asubstantially proppant-free early stage comprising a continuous gasphase into the formation above a fracturing pressure to form a fracturesystem comprising a branched tip region; and injecting one or moreproppant stages, comprising a treatment fluid comprising proppant andhaving a viscosity greater than the early stage, into the formationbehind the early stage to form a propped region of the fracture systemto communicate between the wellbore and the branched tip region.

According to some embodiments, a hybrid method for treating asubterranean formation penetrated by a wellbore comprises injecting asubstantially proppant-free early stage comprising a continuous gasphase, and optionally a mist phase as described herein, into theformation above a fracturing pressure to form a fracture systemcomprising a branched tip region, and injecting one or more proppantstages, comprising a treatment fluid comprising proppant and having aviscosity greater than the early stage, into the formation behind theearly stage to form a propped region of the fracture system tocommunicate between the wellbore and the branched tip region. Accordingto some embodiments, the early stage comprises particles dispersed inthe continuous gas phase, as described above, as a fluid loss controlagent, e.g., particles dispersed in the continuous gas phase comprisingfines having a diameter of less than 50 microns and are substantiallyfree of solids having a diameter greater than 100 microns.

In some embodiments, the early stage comprises particles dispersed inthe continuous gas phase as a fluid loss control agent, e.g., as a mistphase to deposit a fluid loss control agent on the exposed fracturefaces to inhibit fluid loss from the gas treatment fluid stage forimproved fracture efficiency. A “fluid loss control agent,” sometimesreferred to herein as a “fluid loss agent” or “loss agent,” refers to amaterial in the fluid that can inhibit loss of the fluid through contactwith a permeable structure to a region of lower pressure.

In some embodiments of the method, treating a subterranean formationpenetrated by a wellbore comprises injecting, above a fracturingpressure into a fracture in the formation, a gas treatment fluid stagesubstantially free of proppant and comprising a continuous gas phase anda mist phase comprising a liquid or foam dispersed in the continuous gasphase; depositing particles from the mist phase onto a surface of theformation to inhibit fluid loss into a matrix of the formation; andreducing the pressure in the fracture to form a network of conductivegas-fractured flow paths in the formation.

The gas phase in various embodiments may comprise any material ormixture of materials that is a gas at any or all downhole or formationtemperature(s) and pressure(s) used during the gas fracturing, includinga supercritical fluid. As used herein, supercritical refers to a fluidabove both its critical temperature and its critical pressure, whereassubcritical refers to a fluid which is below its critical temperature,or below its critical pressure, or both. Gases, including supercriticalfluids, may have a viscosity at the fracturing conditions equal to orless than about 100 μPa-s. Representative gases for the continuous gasphase include nitrogen, air, carbon dioxide, methane, ethane, and thelike.

In some embodiments, the continuous gas phase comprises a supercriticalfluid, e.g., a supercritical fluid having a viscosity in the range of 10to 100 μPa-s. In some embodiments, the use of a supercritical fluid asthe gas phase inhibits gas leakoff since supercritical fluids generallyhave a higher viscosity than their non-supercritical counterpart gasesand hence a lower permeation rate into the formation matrix.

In some embodiments, the gas phase is a subcritical fluid, and in somefurther embodiments the use of a subcritical gas phase, e.g., with agenerally lower viscosity less than about 10 μPa-s and thus having atendency for a higher leakoff rate which might make them otherwiseimpractical for use in gas fracturing, is facilitated by the presence ofthe leakoff inhibition obtained by the presence of the mist phase.

The mist phase in various embodiments may be any particles (includingfluid or foam droplets) that are suspended or otherwise dispersed as adiscontinuous phase in the continuous gas phase in a disjointed manner,e.g., colloidal particles in an aerosol or larger particles in a gassuspension. The term “dispersion” means a mixture of one substancedispersed in another substance, and may include colloidal ornon-colloidal systems. In this respect, the mist phase can also bereferred to, collectively, as “particle” or “particulate” which termsmay be used interchangeably. As used herein, the term “particle” shouldbe construed broadly. For example, in some embodiments, the particles ofthe current application are fine solids, defined for the purposes hereinas having a particle size less than 10 microns, e.g., 1 to 10 μm, orultrafine solids or colloids, defined for the purposes herein as fineparticles having a particle size less than 1 micron, e.g., 1 to 1000 nm;however, in some other embodiments, the particle(s) can be liquid, foam,emulsified droplets, fine or ultrafine solids coated by or suspended inliquid or foam, etc. The particles comprising the mist phase may have aparticle size distribution that is either monodisperse or polydisperse,e.g., bimodal, trimodal, tetramodal, or the like. Liquid and/or foamparticles whether containing solids or not, are almost always sphericalor nearly spherical, but may be irregular; whereas solid particles maybe spherical or irregular, e.g., with varying degrees of sphericity androundness, according to the API RP-60 sphericity and roundness index.For example, the particle(s) used as fluid loss agents in the mist phasemay have an aspect ratio of more than 2, 3, 4, 5 or 6. Examples of suchnon-spherical particles include, but are not limited to, fibers, flocs,flakes, discs, rods, grains, stars, etc. All such variations should beconsidered within the scope of the current application.

As used herein, “substantially free of proppant” refers to a gastreatment fluid stage to which proppant or other solid particles havinga particle size of 100 microns or more is not present, or if present, ispresent in amounts of less than 0.5 volume percent, or has not beendeliberately added in amounts of more than 0.5 volume percent, by totalvolume of the gas treatment fluid stage, or if a mist phase is present,comprises less than 10 volume percent by volume of the mist phase.

In some embodiments herein, fluid loss control to inhibit loss of thegas phase is effected by plugging at least a portion of micropores inthe formation matrix with a fluid loss control agent such as finesolids, which results in a decrease in permeability and thus a reductionof the gas penetration rate into the formation. In some embodiments, atleast a portion of the micropores may be alternatively or additionallyfilled with a fluid such as liquid, foam, or the like which has a higherviscosity relative to the gas phase, which also contributes to adecreased fluid penetration rate.

According to some embodiments, liquid, foam and/or solid fluid lossagents may be delivered in a form of a mist or vapor, and deposited onthe fracture face, followed by penetration into the pore spaces. In someembodiments, a foam, which generally has a much higher viscosity thanits liquid phase per se, may be used to fill micropores to enhance losscontrol. In some embodiments, an energized liquid may be used to fillmicropores, and may thereafter form a foam in situ upon expansion fromthe fracturing pressure to the formation pressure. Such fluid lossagents in various embodiments may also comprise several components, suchas, for example, clay stabilizing agent(s), surfactant(s), foamingagent(s), corrosion inhibitor(s), gelling agent(s), delayed crosslinkingagent(s), pH agent(s), breaker(s), etc., including combinations thereof.

According to some embodiments, the mist phase particles comprise a sizeof less than 100 microns, e.g., less than 50 microns, less than 20microns, less than 10 microns or less than 1 micron. According to someembodiments, the particles comprise monophasic liquid, emulsion, foam,solids or a combination thereof. According to some embodiments, the mistphase is aqueous, such as, for example, comprised of water, brine, acidsolutions, alkali solutions, or the like. According to some embodiments,the mist phase comprises a hydrophobic phase such as a hydrocarbon,e.g., a subcritical hydrocarbon liquid. As used herein, subcriticalrefers to a material which is below its critical temperature, or belowits critical pressure, or both. In some embodiments, the mist phasecomprises a mixture of water based liquids and organic liquids,including emulsions. As used herein, “emulsion” generally means anysystem with one liquid phase dispersed in another immiscible liquidphase, and may apply to oil-in-water and water-in-oil emulsions,including oil-in-water-in-oil and water-in-oil-in-water emulsions.Invert or reverse emulsions refer to any water-in-oil emulsion in whichoil is the continuous or external phase and water is the dispersed orinternal phase.

According to some embodiments, the mist phase comprises a hydrolyzablecompound. According to some embodiments, the mist phase comprises adegradable oil. In embodiments, the degradable oil is any degradableoleaginous fluid such as, for example, an oleophilic ester, ether,amide, amine, alcohol, glycoside, or combination thereof, and may have asolubility in water of less than 10 wt %, or less than 5 wt %, or lessthan 1 wt % at 25° C. In embodiments, the degradable oil may be selectedfrom the group consisting of oleophilic monocarboxylic acid esterscomprising from 3 to 40 carbon atoms, oleophilic polycarboxylic acidesters comprising from 4 to 40 carbon atoms, oleophilic etherscomprising from 3 to 40 carbon atoms, oleophilic alcohols comprisingfrom 3 to 40 carbon atoms, and combinations thereof. In someembodiments, the degradable oil is non-toxicological.

For purposes herein, a material having solubility in water of less than10 wt %, or less than 5 wt %, or less than 1 wt % at 25° C. is said tobe oleophilic. In some embodiments, the degradable oil may comprise twoor more moieties attached via a functional group, e.g., a carboxylicacid, an alcohol, an amine, an amide, a glycoside, an ether, in whichthe chain length of one of the moieties is from 1 to 40, or from 6 to30, or from 8 to 15 carbon atoms, with the remaining carbon atoms, orhydrogen atom(s) in the case of an alcohol or an amine, forming theother moiety or moieties. In some embodiments, the degradable oilundergoes hydrolysis upon contact with an aqueous solution having a pHfrom about 9 to 14 and/or a pH from about 0 to 5. In some embodiments,the degradable oil has a hydrophilic-lipophilic balance of less than 16,or less than 14, or less than 12, or less than 10, as determinedaccording to Griffin's method on a scale from 0 to 20 as is readilyunderstood by one having minimal skill in the art.

In embodiments, the degradable oil is converted from a relatively waterinsoluble oil into its water soluble components upon exposure totemperature, biological agents, acids, bases, and/or the like presentat, or provided to the intended location of the fluid for a particularuse, e.g., upon or after fracture closure or otherwise after thedegradable oil has been used as a fluid loss agent during the gasfracturing operation. In some embodiments, the degradable oil undergoeshydrolysis at a pH from about 0 to 14, or at a pH of greater than orequal to about 9, e.g., from about 9 to 14 or higher, and/or at a pH ofless than or equal to about 4, e.g., from about 4 to about 0 or less.

In some embodiments, the degradable oil comprises a monocarboxylic acidester having ecologically acceptable components from the class ofso-called non-polluting oils. Examples include esters of “lower”carboxylic acids having from 1 to 10 carbons. Suitable lowermonocarboxylic acids include the reaction products of monofunctionalalcohols, polyfunctional alcohols, and the like. Suitable alcoholsinclude di- to tetra-hydric alcohols, lower alcohols of this type,including having 2 to 6 carbon atoms. Examples of such poly-hydricalcohols include aliphatic glycols and/or propanediols such as ethyleneglycol, 1,2-propanediol and/or 1,3-propanediol. Suitable alcohols can beof natural and/or synthetic origin. Straight-chain and/or branchedalcohols may be used herein.

In some embodiments, the ester oils may be the reaction product oflong-chain acids having from 11 to 40 carbon atoms, which may includeunsaturated and/or polyunsaturated acids. The carboxylic acid radicalspresent can be of vegetable and/or animal origin. Vegetable startingmaterials include, for example, palm oil, peanut oil, castor oil and/orrapeseed oil. The carboxylic acids of animal origin include tallow, fishoils, rendering oils, and the like. Other suitable degradable oilsinclude anchovy oil, castor oil, palm oil, virgin coconut oil, salmonoil, sunflower oil, soy bean oil, cod liver oil, oil, C₁₀₋₂₈ fatty acidC₁₋₁₀ alkyl esters (e.g., fatty acid methyl esters), and the like.

In some embodiments, the ester-containing degradable oil may becontacted with dilute alkali to produce a salt and an alcohol. Theformation of alcohol reduces the surface tension and alters wettability.In the case of an emulsion with water as a continuous phase and theester based oil as the dispersed phase, the hydrolysis of the oil willreduce the surface tension of the continuous water phase and enhancewettability, which may likewise enhance the flowback and cleanup in someembodiments.

In some embodiments, the degradable oleaginous oil may include an ester,which, when contacted with an acid will hydrolyze to produce an acid andan alcohol, which may reduce the surface tension and enhance thewettability of the formation.

In some embodiments, the degradable oil is non-toxicological, meaning itdoes not degrade into toxic substances, or substances which have anacute toxicity such that they would be considered hazardous or toxic inthe intended environment. In some embodiments, the degradable oilcomprises less than about 1 wt % aromatic content, or less than about0.5 wt %, or less than 0.1 wt % aromatic content.

In some embodiments, the degradable oil comprises a linear alpha olefin,which may be of natural or synthetic origin.

In some embodiments, the degradable oil may comprise various substitutedand/or fully esterified triglycerides.

In some embodiments, the degradable oil may comprise C₂-C₁₂ alkoxylates,e.g., ethoxylates, propoxylates, and/or the like, including alkoxylatedalcohols, acids, polyethers, amines, amides, glycosides, and/or thelike.

Suitable degradable oils include FlexiSOLV® dibutyl ester (DBE)(INVISTA, Koch Industries, USA), which are high boiling oxygenatedsolvents that are miscible with organic solvents, low odor andflammability, comprising refined dimethyl esters of adipic, glutaric andsuccinic acids. The DBE esters undergo reactions expected of the estergroup such as hydrolysis and transesterification. At low and high pH theDBE esters are hydrolyzed to the corresponding acids, their salts andalcohol. The dibutyl ester components of dimethyl succinate, dimethylglutarate and dimethyl adipate are readily biodegradable.

Suitable examples further include AMSOIL® biodegradable oil (AMSOILINC., USA) which is designed to biodegrade when subjected to sunlight,water and microbial activity. The biodegradable oil is a blend of oleicvegetable oils and customized synthetic esters. AMSOIL® oil exhibitshigh biodegradability and low aquatic toxicity, along with superioroxidative stability, and low temperature performance. It containsanti-oxidants that ensure long oil life and foam inhibitors that promoteproblem-free operation. It is hydrolytically stable and ideal for usewhere water contamination is a problem.

Other suitable degradable oils include those disclosed in U.S. Pat. Nos.4,374,737; 4,614,604; 4,802,998; 5,232,910; 5,252,554; 5,254,531;5,318,954; 5,318,956; 5,348,938; 5,403,822; 5,441,927; 5,461,028;5,663,122; 5,755,892; 5,846,601; RE 36,066; 5,869,434; 6,022,833;6,122,860; 6,165,946; 6,289,989; 6,350,788; 6,716,799; 6,806,235;6,828,279; 7,041,738; 7,666,820; 7,741,248; and 8,236,735; all of whichare hereby incorporated by reference.

According to some embodiments, the mist phase comprises a materialselected from the group consisting of esters, polyamines, polyethers andcombinations thereof. According to some embodiments, the method furthercomprises degrading the mist particles deposited on the formationsurface to facilitate conductivity.

According to some embodiments, the mist phase comprises a foaming agentand/or may be a foam. The term “foam” refers to a stable mixture ofgas(es) and liquid(s) that form a two-phase system. Foam is generallydescribed by its foam quality, i.e. the ratio of gas volume to the foamvolume (fluid phase of the treatment fluid), i.e., the ratio of the gasvolume to the sum of the gas plus liquid volumes). If the foam qualityis between 52% and 95%, the fluid is usually called foam. Below 52%, thefoam may be referred to as an “energized fluid.” Above 95%, foam isgenerally changed to mist, i.e., dispersed liquid or foam droplets in acontinuous gas phase. In the present patent application, the term “foam”also encompasses two-phase energized liquids and refers to any stablemixture of gas and liquid, regardless of the foam quality.

According to some embodiments, the mist phase comprises fine solids lessthan 10 microns, or ultrafine solids less than 1 micron, or 30 nm to 1micron. According to some embodiments, the fine solids are fluid losscontrol agents such as γ-alumina, colloidal silica, CaCO3, SiO2,bentonite etc.; and may comprise particulates with different shapes suchas glass fibers, flocs, flakes, films; and any combination thereof orthe like. Colloidal silica, for example, may function as an ultrafinesolid loss control agent, depending on the size of the micropores in theformation, as well as a gellant and/or thickener in any associatedliquid or foam phase. As representative leakoff control agents, theremay be mentioned latex dispersions, water soluble polymers, submicronparticulates, particulates with an aspect ratio higher than 1, or higherthan 6, combinations thereof and the like, such as, for example,crosslinked polyvinyl alcohol microgel. The fluid loss agent can be, forexample, a latex dispersion of polyvinylidene chloride, polyvinylacetate, polystyrene-co-butadiene; a water soluble polymer such ashydroxyethylcellulose (HEC), guar, copolymers of polyacrylamide andtheir derivatives; particulate fluid loss control agents in the sizerange of 30 nm to 1 micron, such as γ-alumina, colloidal silica, CaCO₃,SiO₂, bentonite etc.; particulates with different shapes such as glassfibers, flakes, films; and any combination thereof or the like. Fluidloss agents can if desired also include or be used in combination withacrylamido-methyl-propane sulfonate polymer (AMPS).

In embodiments, the leak-off control agent comprises a fine or ultrafinesolid that may removable by degradation, dissolution, melting, or thelike. In some embodiments, the fluid loss agent may be a reactive solid,e.g., a hydrolysable material such as polyglycolic acid (PGA),polylactic acid (PLA), PGA-PLA copolymers, or the like; or it caninclude a soluble or solubilizable material such as a wax, anoil-soluble resin, or another material soluble in hydrocarbons, orcalcium carbonate or another material soluble at low pH; and so on. Inembodiments, the leak-off control agent comprises a reactive solidselected from ground quartz, oil soluble resin, degradable rock salt,clay, zeolite or the like. In other embodiments, the leak-off controlagent comprises one or more of magnesium hydroxide, magnesium carbonate,magnesium calcium carbonate, calcium carbonate, aluminum hydroxide,calcium oxalate, calcium phosphate, aluminum metaphosphate, sodium zincpotassium polyphosphate glass, and sodium calcium magnesiumpolyphosphate glass, or the like.

According to some embodiments, the mist phase comprises from 0.5 to 10percent by volume, or less than 5 percent by volume of the gas treatmentfluid stage, based on the total volume of the gas treatment fluid stage,as determined at the bottom hole pressure and temperature where itenters the fracture.

According to some embodiments, the gas treatment fluid stage is injectedas a pad or pre-pad stage and the method further comprises: injectingone or more proppant stages into the fracture following the gastreatment fluid stage prior to fracture closure.

According to some embodiments of the hybrid method, the one or moreproppant stages comprise slickwater and a proppant loading from 0.01 to0.6 g/mL of carrier fluid (0.1-5 ppa).

According to some embodiments of the hybrid method, the one or moreproppant stages comprise an aqueous or oil-based carrier fluid, aviscosifier and a proppant loading of at least 0.6 g/mL of carrier fluid(5 ppa).

According to some embodiments of the hybrid method, the one or moreproppant stages comprise a high solid content fluid, e.g., a slurrywherein a sum of all the particulates in the fracturing slurry isgreater than about 16 pounds per gallon of the carrier fluid, or isgreater than about 23 pounds per gallon of the carrier fluid, or isgreater than 30 pounds per gallon of the carrier fluid, as disclosed inU.S. Pat. No. 7,784,541, herewith incorporated by reference in itsentirety.

According to some embodiments of the hybrid method, the one or moreproppant stages comprise alternating proppant concentration betweensuccessive proppant stages and/or alternating stages ofproppant-containing hydraulic fracturing fluids contrasting in theirproppant-settling rates to form proppant clusters which become pillarsthat prevent the fracture from completely closing, as described in U.S.Pat. No. 6,776,235, herewith incorporated by reference in its entirety.

According to some embodiments of the hybrid method, the method mayfurther comprise injecting one or more substantially proppant-freestages between successive ones of the proppant stages, as described inPatent Publication U.S. 2008/0135242, herewith incorporated by referencein its entirety.

According to some embodiments of the hybrid method, the one or moreproppant stages comprise carrier fluid, proppant and agglomerant,wherein injection of the one or more proppant stages forms asubstantially uniformly distributed mixture of the proppant and theagglomerant, and wherein the proppant and the agglomerant havedissimilar velocities in the fracture system to transform thesubstantially uniformly distributed mixture into areas that are rich inproppant and areas that are substantially free of proppant, as describedin U.S. application Ser. No. 13/832,938, filed Mar. 15, 2013, herewithincorporated herein by reference in its entirety.

According to some embodiments of the hybrid method, the one or moreproppant stages comprise proppant and shapeshifting particles dispersedin a carrier fluid, and further comprising changing a conformation ofthe shapeshifting particles in the fracture system, as described in U.S.application Ser. No. 14/056,665, filed Oct. 17, 2013 herewithincorporated herein by reference in its entirety.

According to some embodiments of the hybrid method, the method mayfurther comprise: continuously distributing the proppant into thefracture system during the injection of the one or more proppant stages;aggregating the proppant distributed into the fracture to formspaced-apart clusters in the fracture system; anchoring at least some ofthe clusters in the fracture system to inhibit aggregation of at leastsome of the clusters; and reducing pressure in the fracture system toform interconnected, hydraulically conductive channels between theclusters in the propped region of the fracture system, as described inU.S. application Ser. No. 13/974,203, filed Aug. 23, 2013, herewithincorporated herein by reference in its entirety.

According to some embodiments of the hybrid method, the method mayfurther comprise: injecting the one or more proppant stages at acontinuous rate with a continuous proppant concentration; whilemaintaining the continuous rate and proppant concentration, successivelyalternating concentration modes of an anchorant in the one or moreproppant stages between a plurality of relatively anchorant-rich modesand a plurality of anchorant-lean modes, as also described in U.S.application Ser. No. 13/974,203, filed Aug. 23, 2013, herewithincorporated herein by reference in its entirety.

According to some embodiments of the hybrid method, the method mayfurther comprise: providing a treatment slurry comprising an energizedfluid, the proppant and an anchorant, injecting the treatment slurryinto a fracture to form a substantially uniformly distributed mixture ofthe solid particulate and the anchorant, and transforming thesubstantially uniform mixture into areas that are rich in solidparticulate and areas that are substantially free of solid particulate,as described in U.S. provisional Application Ser. No. 61/873,185, filedSep. 3, 2013, herewith incorporated herein by reference in its entirety.

According to some embodiments of the hybrid method, the proppantstage(s) may be injected into the fracture system using any one of theavailable heterogeneous proppant placement techniques, such as, forexample, those disclosed in U.S. Pat. No. 3,850,247; U.S. Pat. No.7,281,581; U.S. Pat. No. 7,325,608; U.S. Pat. No. 7,044,220; WO2007/086771; each of which is hereby incorporated herein by reference inits entirety.

According to some embodiments of the hybrid method, the early stage isinjected as a pre-pad stage and the method further comprises injecting afoam or liquid pad stage into the fracture system following the pre-padstage prior to the one or more proppant stages. According to someembodiments of the hybrid method, the method may further compriseinjecting a flush stage into the fracture system following the one ormore proppant stages.

According to some embodiments, a reservoir fluid production systemcomprises a wellbore penetrating a subterranean formation; and thefracture system obtained by the hybrid method described herein in fluidcommunication with the wellbore. According to some embodiments, thebranched tip region of the fracture system is substantiallyproppant-free.

According to some embodiments, a system to treat a subterraneanformation, comprises: a subterranean formation penetrated by a wellbore;a gas injection unit to supply a gas treatment fluid stage,substantially free of proppant and comprising a continuous gas phase, tothe formation above a fracturing pressure to form a fracture systemcomprising a branched tip region; and a pump system to supply one ormore proppant stages, comprising a treatment fluid comprising proppantand having a viscosity greater than the gas treatment fluid stage, intothe fracture system behind the gas treatment fluid stage to form apropped region of the fracture system to communicate between thewellbore and the branched tip region.

With reference to FIG. 1, an initial gas fracturing stage involvesinjecting the gas stage as described herein through the wellbore 10 intothe formation 12 to form a fracture system 14 having a relativelybranched, dendritic tip region 16 extending away from the wellbore. Thewidth of the fracture is generally dependent on the viscosity of thefracturing fluid, and since in embodiments herein the continuous gasphase has a low viscosity, e.g., less than 100 μPa-s, the tip region 16may have fractures that are too narrow to receive proppant.

FIG. 2 shows the fracture of FIG. 1 following subsequent injection ofone or more proppant stages into the fracture system 14 forming arelatively wide fracture, i.e., one which is capable of receiving atreatment stage containing proppant in the near-wellbore fracture region18 of the fracture system 14′. In some embodiments, the proppant isplaced or formed into clusters according to any of various heterogeneousproppant placement techniques, e.g., by introducing alternatingcluster-forming and channel-forming substages, such as, for example,alternating proppant-laden and proppant-lean substages.

FIG. 3 schematically illustrates the near-wellbore portion 18 of thefracture system 14′ as seen along the lines 3-3 of FIG. 2, followingformation of proppant pillars 20 generally corresponding to proppantclusters placed or formed in accordance with a heterogeneous proppantplacement technique, and fracture closure, according to some embodimentsto form the ultimate fracture system 14″. In the fracture system 14″ thegas fractured tip region 16 (see FIG. 2) is in fluid communication withthe propped fracture region 18 via intersections 24 with gas-fracturedregions and/or via intersections 26 with additional propped fractureregions, which may communicate with further regions of the fracturenetwork. Reservoir fluid from the tip region 16 may flow throughhydraulically conductive channels 22 around the pillars 20 (and/orthrough proppant pillars 20 and/or proppant filling the fracture region18, according to some embodiments where the proppant pillars or otherfracture fill mode is permeable).

Accordingly, the present disclosure provides the following embodiments,among others:

-   1. A method for treating a subterranean formation penetrated by a    wellbore, comprising:    -   injecting a substantially proppant-free early stage comprising a        continuous gas phase into the formation above a fracturing        pressure to form a fracture system comprising a branched tip        region; and    -   injecting one or more proppant stages, comprising a treatment        fluid comprising proppant and having a viscosity greater than        the early stage, into the formation behind the early stage to        form a propped region of the fracture system to communicate        between the wellbore and the branched tip region.-   2. The method of embodiment 1, wherein the early stage comprises    particles dispersed in the continuous gas phase as a fluid loss    control agent, forming a mist phase.-   3. The method of embodiment 2, wherein the mist phase comprises    particles having a size of less than 100 microns, or less than 50    microns, or less than 20 microns, or less than 10 microns, or from 1    to 10 microns, or less than 1 micron, or from 1 to 1000 nm, wherein    the particles comprise monophasic liquid, emulsion, foam, solids or    a combination thereof.-   4. The method of embodiment 2 or embodiment 3, wherein the mist    phase is aqueous.-   5. The method of any one of embodiments 2 to 4, wherein the mist    phase comprises a hydrocarbon.-   6. The method of any one of embodiments 2 to 5, wherein the mist    phase comprises a hydrolyzable compound.-   7. The method of any one of embodiments 2 to 6, wherein the mist    phase comprises a degradable oil.-   8. The method of any one of embodiments 2 to 7, wherein the mist    phase comprises a material selected from the group consisting of    esters, polyamines, polyethers and combinations thereof.-   9. The method of any one of embodiments 2 to 8, wherein the mist    phase comprises a foaming agent.-   10. The method of any one of embodiments 2 to 9, wherein the mist    phase comprises fine solids, or ultrafine solids.-   11. The method of any one of embodiments 2 to 10, further comprising    degrading the mist particles deposited on the formation surface to    facilitate conductivity.-   12. The method of any one of embodiments 2 to 11, wherein the mist    phase comprises from 0.5 to 10 percent by volume, or less than 5    percent by volume, based on the total volume of the gas treatment    fluid stage.-   13. The method of any one of embodiments 2 to 12, wherein the mist    phase comprises less than 5 percent by volume of the gas treatment    fluid stage, based on the total volume of the gas treatment fluid    stage.-   14. The method of any one of embodiments 1 to 13, wherein the one or    more proppant stages comprise slickwater and a proppant loading from    0.01 to 0.6 g/mL of carrier fluid (0.1-5 ppa).-   15. The method of any one of embodiments 1 to 13, wherein the one or    more proppant stages comprise an aqueous or oil-based carrier fluid,    a viscosifier and a proppant loading of at least 0.6 g/mL of carrier    fluid (5 ppa).-   16. The method of any one of embodiments 1 to 15, wherein the one or    more proppant stages comprise a high solid content fluid.-   17. The method of any one of embodiments 1 to 16, wherein the one or    more proppant stages comprise alternating proppant concentration    between successive proppant stages.-   18. The method of any one of embodiments 1 to 17, further comprising    injecting one or more substantially proppant-free stages between    successive ones of the proppant stages.-   19. The method of any one of embodiments 1 to 18, wherein the one or    more proppant stages comprise carrier fluid, proppant and    agglomerant, wherein injection of the one or more proppant stages    forms a substantially uniformly distributed mixture of the proppant    and the agglomerant, and wherein the proppant and the agglomerant    have dissimilar velocities in the fracture system to transform the    substantially uniformly distributed mixture into areas that are rich    in proppant and areas that are substantially free of proppant.-   20. The method of any one of embodiments 1 to 19, wherein the one or    more proppant stages comprise proppant and shapeshifting particles    dispersed in a carrier fluid, and further comprising changing a    conformation of the shapeshifting particles in the fracture system.-   21. The method of any one of embodiments 1 to 20, further    comprising:    -   continuously distributing the proppant into the fracture system        during the injection of the one or more proppant stages;    -   aggregating the proppant distributed into the fracture to form        spaced-apart clusters in the fracture system;    -   anchoring at least some of the clusters in the fracture system        to inhibit settling and/or aggregation of at least some of the        clusters;    -   reducing pressure in the fracture system to form interconnected,        hydraulically conductive channels between the clusters in the        propped region of the fracture system.-   22. The method of any one of embodiments 1 to 21, further    comprising:    -   injecting the one or more proppant stages at a continuous rate        with a continuous proppant concentration;    -   while maintaining the continuous rate and proppant        concentration, successively alternating concentration modes of        an anchorant in the one or more proppant stages between a        plurality of relatively anchorant-rich modes and a plurality of        anchorant-lean modes.-   23. The method of any one of embodiments 1 to 22, wherein the early    stage is injected as a pre-pad stage and the method further    comprises injecting a foam or liquid pad stage into the fracture    system following the pre-pad stage prior to the one or more proppant    stages.-   24. The method of any one of embodiments 1 to 23, further comprising    injecting a flush stage into the fracture system following the one    or more proppant stages.-   25. A reservoir fluid production system comprising:    -   a wellbore penetrating a subterranean formation; and    -   the fracture system obtained by the method of any one of        embodiments 1 to 24 in fluid communication with the wellbore.-   26. The system of embodiment 25, wherein the branched tip region of    the fracture system is substantially proppant-free.-   27. A system to treat a subterranean formation, comprising:    -   a subterranean formation penetrated by a wellbore;    -   a gas injection unit to supply a gas treatment fluid stage,        substantially free of proppant and comprising a continuous gas        phase, to the formation above a fracturing pressure to form a        fracture system comprising a branched tip region; and    -   a pump system to supply one or more proppant stages, comprising        a treatment fluid comprising proppant and having a viscosity        greater than the gas treatment fluid stage, into the fracture        system behind the gas treatment fluid stage to form a propped        region of the fracture system to communicate between the        wellbore and the branched tip region.

While the embodiments have been illustrated and described in detail inthe drawings and foregoing description, the same is to be considered asillustrative and not restrictive in character, it being understood thatonly some embodiments have been shown and described and that all changesand modifications that come within the spirit of the embodiments aredesired to be protected. It should be understood that while the use ofwords such as ideally, desirably, preferable, preferably, preferred,more preferred or exemplary utilized in the description above indicatethat the feature so described may be more desirable or characteristic,nonetheless may not be necessary and embodiments lacking the same may becontemplated as within the scope of the disclosure, the scope beingdefined by the claims that follow. In reading the claims, it is intendedthat when words such as “a,” “an,” “at least one,” or “at least oneportion” are used there is no intention to limit the claim to only oneitem unless specifically stated to the contrary in the claim. When thelanguage “at least a portion” and/or “a portion” is used the item caninclude a portion and/or the entire item unless specifically stated tothe contrary.

We claim:
 1. A method for treating a subterranean formation traversed bya wellbore, comprising: injecting a substantially proppant-free earlystage comprising a continuous gas phase into the formation above afracturing pressure to form a fracture system comprising a branched tipregion; and injecting a proppant stage comprising a treatment fluidcomprising proppant, wherein the viscosity of the proppant stage isgreater than the early stage, wherein the injecting the proppant stagebehind the early stage forms a propped region of the fracture system forcommunication between the wellbore and the branched tip region.
 2. Themethod of claim 1, wherein the early stage comprises particles dispersedin the continuous gas phase as a fluid loss control agent.
 3. The methodof claim 2, wherein the particles dispersed in the continuous gas phasecomprise fines having a diameter of less than 50 microns and aresubstantially free of solids having a diameter greater than 100 microns.4. The method of claim 2, wherein the particles dispersed in thecontinuous gas phase comprise from 0.5 to 10 percent by volume based onthe total volume of the gas stage.
 5. The method of claim 1, wherein theearly stage comprises liquid or foam phase particles dispersed as a mistin the gas phase.
 6. The method of claim 5, wherein the dispersed liquidor foam phase particles comprise microdroplets having a diameter of lessthan 100 microns.
 7. The method of claim 5, wherein the particlesdispersed in the continuous gas phase are aqueous and comprise a foamingagent.
 8. The method of claim 5, wherein the mist further comprisesfines having a diameter of less than 50 microns and is substantiallyfree of solids having a diameter greater than 100 microns.
 9. The methodof claim 1, wherein the one or more proppant stages comprise slickwaterand a proppant loading from 0.01 to 0.6 g/mL of carrier fluid (0.1-5ppa).
 10. The method of claim 1, wherein the one or more proppant stagescomprise an aqueous or oil-based carrier fluid, a viscosifier and aproppant loading of at least 0.6 g/mL of carrier fluid (5 ppa).
 11. Themethod of claim 1, wherein the one or more proppant stages comprise ahigh solid content fluid.
 12. The method of claim 1, wherein the one ormore proppant stages comprise alternating proppant concentration betweensuccessive proppant stages.
 13. The method of claim 1, furthercomprising injecting one or more substantially proppant-free stagesbetween successive ones of the proppant stages.
 14. The method of claim1, wherein the one or more proppant stages comprise carrier fluid,proppant and agglomerant, wherein injection of the one or more proppantstages forms a substantially uniformly distributed mixture of theproppant and the agglomerant, and wherein the proppant and theagglomerant have dissimilar velocities in the fracture system totransform the substantially uniformly distributed mixture into areasthat are rich in proppant and areas that are substantially free ofproppant.
 15. The method of claim 1, wherein the one or more proppantstages comprise proppant and shapeshifting particles dispersed in acarrier fluid, and further comprising changing a conformation of theshapeshifting particles in the fracture system.
 16. The method of claim1, further comprising: continuously distributing the proppant into thefracture system during the injection of the one or more proppant stages;aggregating the proppant distributed into the fracture to formspaced-apart clusters in the fracture system; anchoring at least some ofthe clusters in the fracture system to inhibit aggregation of at leastsome of the clusters; reducing pressure in the fracture system to forminterconnected, hydraulically conductive channels between the clustersin the propped region of the fracture system.
 17. The method of claim 1,further comprising: injecting the one or more proppant stages at acontinuous rate with a continuous proppant concentration; whilemaintaining the continuous rate and proppant concentration, successivelyalternating concentration modes of an anchorant in the one or moreproppant stages between a plurality of relatively anchorant-rich modesand a plurality of anchorant-lean modes.
 18. The method of claim 1,wherein the early stage is injected as a pre-pad stage and the methodfurther comprises injecting a foam or liquid pad stage into the fracturesystem following the pre-pad stage prior to the one or more proppantstages.
 19. The method of claim 1, further comprising injecting a flushstage into the fracture system following the one or more proppantstages.
 20. A reservoir fluid production system comprising: a wellborepenetrating a subterranean formation; and the fracture system obtainedby the method of claim 1 in fluid communication with the wellbore. 21.The system of claim 20, wherein the branched tip region of the fracturesystem is substantially proppant-free.
 22. A system to treat asubterranean formation, comprising: a subterranean formation penetratedby a wellbore; a gas injection unit to supply a gas treatment fluidstage, substantially free of proppant and comprising a continuous gasphase, to the formation above a fracturing pressure to form a fracturesystem comprising a branched tip region; and a pump system to supply oneor more proppant stages, comprising a treatment fluid comprisingproppant and having a viscosity greater than the gas treatment fluidstage, into the fracture system behind the gas treatment fluid stage toform a propped region of the fracture system to communicate between thewellbore and the branched tip region.